Method for distinguishing authenticity of high-pressure physical property parameters of oil reservoirs

ABSTRACT

A method for distinguishing an authenticity of high-pressure physical property parameters of oil reservoirs is provided. The method includes: collecting the high-pressure physical property parameters, screening a standard well, calculating a pump efficiency by means of formulas, then calculating an absolute value Δ=|η theory −η reality | of each group of absolute errors, and taking a smallest absolute value Δ min  of the absolute error. wherein Δ min ≤ε, ε is a set accuracy, generally, 0≤ε≤0.02, and the high-pressure physical property parameters corresponding to a group of the theoretical pump efficiency η theory  and the real pump efficiency η reality  are real high-pressure physical property parameters of an oil reservoir to be distinguished. The method provides a fast, simple and practical means for distinguishing correct high-pressure physical property parameters. The method is applicable to an oil well in a certain zone of an oil reservoir to be determined.

TECHNICAL FIELD

The present invention relates to the technical field of petroleum engineering, particularly the technical field of exploration of oil wells.

BACKGROUND

High-pressure physical property parameters are important parameters that are indispensable for determining oil reservoir types, formulating development plans and performing oil reservoir engineering calculation, and are the basis for studying oil field driving types, determining oil field exploitation modes, calculating oil field reserves and selecting oil well working systems.

At present, there are three main methods for obtaining the high-pressure physical property parameters:

1. Laboratory determination: for unsaturated oil reservoirs of which the saturation pressure is lower than the original formation pressure, during oil tests and production tests, when the flowing bottom hole pressure is higher than the saturation pressure, representative formation oil samples are obtained through a bottom hole sampler, and then, the high-pressure physical property parameters are determined in a laboratory.

2. Calculation by means of existing parameter-related charts: if there is no laboratory determination data or representative formation oil samples cannot be obtained, high-pressure physical property parameter values of formation crude oil can be found through charts.

3. Prediction by means of empirical formulas: when sampling conditions are not available and the parameters cannot be found from charts, some empirical formulas published in some countries are generally used to predict high-pressure physical properties.

The laboratory determination requires undeveloped wells and needs to meet a series of harsh conditions, such as bottom hole pressure higher than the expected original saturation pressure, no water or water content of no more than 5%, stable oil and gas flow, and no intermittency. Due to the complex composition of crude oil, the charts are often not accurate enough. The empirical formulas also have the problem of the scope of application. Therefore, the experimental method, the plate method and the empirical formula method all need to meet certain conditions and are not accurate enough. In particular, there is no easy method to determine the authenticity of the high-pressure physical property parameter values.

SUMMARY

An objective of the present invention is to provide a fast, simple and accurate method for distinguishing the authenticity of high-pressure physical property parameters of oil reservoirs.

A technical solution of the present invention includes the following steps:

1) collecting the high-pressure physical property parameters: collecting high-pressure physical property parameter data of the sampled wells of an oil reservoir to be distinguished, including gas-oil ratio GOR, solubility coefficient α, saturation pressure P_(b), formation crude oil density ρ_(o), and formation crude oil viscosity μ_(o);

2) screening a standard well: determining the standard well from multiple pumping wells continuously exploited in the same block and the same zone as the sampled well, the so-called standard well is the one whose indicator diagram of the oil well reflects that the pump does not leak and its oil tube string does not leak, and in the multiple oil wells, the standard well has the lowest rate of water content, the highest liquid yield and the largest submergence in the multiple oil wells;

3) calculating pump efficiency: substituting each group of high-pressure physical property parameters collected in the step 1) into the following formula, and calculating the theoretical pump efficiency η_(theory) and the real pump efficiency η_(reality) of the standard well using the related data of the standard well in the step 2):

$\eta_{theory} = {{\frac{S - \lambda}{S}\beta} - \frac{Q_{leak}}{Q_{theory}}}$ $\lambda = {\frac{\pi\; D^{2}\rho\;{gh}}{4\; E}\left( {\frac{L_{1}}{f_{1}} + \frac{L_{2}}{f_{2}} + \ldots + \frac{L_{n}}{f_{n}} + \frac{L_{p}}{f_{t}}} \right)}$ $\beta = \frac{1}{1 + \frac{\left( {{GOR} - {\alpha\; P_{s}}} \right)\left( {1 - f_{w}} \right)}{\left( {{10\; P_{s}} + 1} \right)}}$

when P_(s)≥P_(b), making P_(s)=P_(b), where if its oil tubing string is anchored, L_(p)/f_(t) is not included in λ;

η_(reality) =Q _(reality) /Q _(theory)*100%

Q _(theory) =πD ² ρgSN/4

Q _(leak) =πDρgδ ³ h/(12L _(p)/μ)

where

Q_(reality) represents the real output of the oil well;

Q_(theory) represents the theoretical displacement of the oil well;

Q_(leak) represents the pump leakage;

GOR represents the gas-oil ratio and the unit is m³/m³; α represents the solubility coefficient and the unit is m³/(m³·Mpa); P_(b) represents the saturation pressure and the unit is Mpa;

λ represents the stroke loss of the standard well and the unit is m; β represents the gas influence coefficient of the standard well, dimensionless; D represents the pump diameter of the standard well and the unit is m; h represents the pump lift of the standard well and the unit is m; L₁, L₂ and L_(n) respectively represent the lengths of the first, second and n-level rods of the standard well and the unit is m; f₁, f₂ and f_(n) respectively represent the cross-sectional areas of the first, second and n-level rods of the standard well and the unit is m²; L_(p) represents the pump setting depth of the standard well and the unit is m; f_(t) represents the cross-sectional area of the metal part of the tubing of the standard well and the unit is m²; E represents the elastic modulus of the steel of the pumping rod in the standard well, 2.1*10⁷N/cm²; P_(s) represents the submergence pressure of the standard well and the unit is Mpa; f_(w) represents the rate of water content in the standard well; S represents the stroke length of the standard well and the unit is m; N represents the stroke frequency of the standard well and the unit is 1/min; g represents the gravity acceleration in the standard well and the unit is m/s²; δ represents the annular gap size between the pump plunger and the pump cylinder of the standard well and the unit is m; L_(pl) represents the length of the pump plunger of the standard well and the unit is m; μ represents the hydrodynamic viscosity in the standard well and the unit is Pa. S;

some of the above parameters may be calculated from more basic parameters:

mixed liquid density: ρ=(1−f _(w))*ρ_(o) +f _(w)*ρ_(w)

effective head: h=h _(dynamic)+1000*(p _(oil) −p _(casing))*g/ρ

submergence pressure: P _(s) =p _(casing)+(h _(setting) −h _(dynamic))*ρ_(o) *g/1000

hydrodynamic viscosity: μ=f _(w)+(1−f _(w))*μ_(o)

where f_(w) represents the water content of the pumped liquid of the standard well and the unit is %; ρ_(o) represents the formation crude oil density and the unit is t/m³; ρ_(w) represents the water density and the unit is t/m³; h_(dynamic) represents the dynamic liquid level depth of the standard well and the unit is m; hsettm_(g) represents the pump setting depth of the standard well and the unit is m; p_(oil) represents the wellhead oil pressure of the standard well and the unit is Mpa; p_(casing) represents the casing pressure of the standard well and the unit is Mpa; μ_(o) represents the formation crude oil viscosity and the unit is Pa. S;

4) screening results: after calculation in the step 3), for a group of standard wells screened in the step 2) and each group of high-pressure physical property parameters, obtaining a group of (η_(theory), η_(reality)) data, and for each group of (η_(theory), η_(reality)) data, calculating the absolute value Δ=|η_(theory)−η_(reality)|, and taking the smallest absolute value Δ_(min) of the absolute error:

Δ_(min)=min|η_(theory)−η_(reality)|

where if Δ_(min) meets the following condition:

Δmin≤ε (ε is the set accuracy, generally, 0≤ε≤0.02),

the high-pressure physical property parameters corresponding to this group of (η_(theory), η_(reality)) are the real high-pressure physical property parameters of a certain zone of this oil reservoir. The present invention provides a fast, simple and practical means for distinguishing correct high-pressure physical property parameters. The present invention is applicable to those oil wells in a certain zone of an oil reservoir whose high-pressure property parameters is to be determined.

DETAILED DESCRIPTION OF THE EMBODIMENTS

I. Distinguishing of high-pressure physical property parameters of a certain zone (such as Ef1) of a certain oil reservoir:

1. Collect high-pressure physical property parameters of all oil wells obtained high-pressure physical properties (called sampled wells) in the zone Ef1 of this oil reservoir.

Gas-oil ratio Solubility Saturation Crude oil Crude oil GOR coefficient α pressure density viscosity Sampled (m³/ (m³/ Pb ρ_(o) μ_(o) well m³) (m³ · Mpa)) (Mpa) (t/m³) (Pa · S) Zhuang 2-9 12.8 4.29 2.65 0.8528 15.66 Wei 2-22 18.8 4.24 3.82 0.8633 9.39 Wei 2-15 26 5.61 4.02 0.8662 9.39 Chen 3-7 74.9 2.7 6.96 0.89 20.67

2. Standard wells are determined according to the following steps:

(1) m oil wells with no leakage of the pump and no leakage of the oil tubing string are selected according to the indicator diagram of each of all oil wells of this reservoir zone.

(2) The m oil wells are sorted according to the water content, and the first n oil wells with the lowest water content are selected in the m selected wells.

(3) The n oil wells are sorted according to the liquid yield, and the first p oil wells with the highest liquid yield are selected in the n selected wells.

(4) The p oil wells are sorted according to the submergence, and the first q oil wells with the highest submergence are selected as standard wells in the p selected wells.

The above steps, (2), (3), and (4), are interchangeable.

The results are as follows:

Dynamic Standard Liquid Water liquid Oil Casing Stroke Pump Pump well yield content level pressure pressure Stroke frequency diameter depth Wei 8 17.3 83.1 692.2 0.7 0.6 3 2.96 44 946.64 Ping 3

3. The data collected in step 1 and step 2 is substituted into the following formula, and the theoretical pump efficiency η_(theory) and the real pump efficiency η_(reality) of the standard wells are calculated respectively corresponding to the high-pressure physical property parameters of the sampled wells:

$\eta_{theory} = {{\frac{S - \lambda}{S}\beta} - \frac{Q_{leak}}{Q_{theory}}}$ $\lambda = {\frac{\pi\; D^{2}\rho\;{gh}}{4\; E}\left( {\frac{L_{1}}{f_{1}} + \frac{L_{2}}{f_{2}} + \ldots + \frac{L_{n}}{f_{n}} + \frac{L_{p}}{f_{t}}} \right)}$ $\beta = \frac{1}{1 + \frac{\left( {{GOR} - {\alpha\; P_{s}}} \right)\left( {1 - f_{w}} \right)}{\left( {{10\; P_{s}} + 1} \right)}}$

(when P_(s)≥P_(b), making P_(s)=P_(b), where if an oil pipe is anchored, L_(p)/f_(t) is not included in λ).

Pump leakage: Q _(leak) =πDμgδ ³ h/(12L _(p)/μ).

Theoretical displacement of oil well: Q _(theory) =πD ² μgSN/4.

Real pump efficiency of oil well: η_(reality) =Q _(reality) /Q _(theory)*100%.

Mixed liquid density: ρ=(1−f _(w))*ρ_(o) +f _(w)*ρ_(w).

Effective head: h=h _(dynamic)+1000*(p _(oil) −p _(casing))*g/ρ.

Submergence pressure: P _(s) =p _(casing)+(h _(setting) −h _(dynamic))*ρ_(o) *g/1000.

Hydrodynamic viscosity: μ=f _(w)+(1−f _(w))*μ_(o)

The following results are obtained:

Standard Sampled Real pump Theoretical pump well well efficiency η_(reality) efficiency η_(theory) Δ Wei 8 Ping 3 Zhuang 2-9 0.912 0.942 0.030 Wei 8 Ping 3 Wei 2-22 0.912 0.911 0.001 Wei 8 Ping 3 Wei 2-15 0.912 0.894 0.018 Wei 8 Ping 3 Chen 3-7 0.912 0.684 0.228

4. Each group of theoretical pump efficiency η_(theory) and real pump efficiency η_(reality) are substituted into the following formula:

Δ=|η_(theory)−η_(reality)|.

The absolute value of the absolute error of each group of theoretical pump efficiency η_(theory) and real pump efficiency η_(reality) is respectively obtained and listed in the 5th column of the above table.

It can be seen from the table that the Δ obtained by the standard well Wei 8 Ping 3 using the high-pressure physical property parameters of the well Wei 2-22 meets the following relationship:

Δ_(min)=min|η_(theory)−η_(reality)|, and Δ_(min)≤ε (here, assuming that ε=0.001).

It can be confirmed that corresponding to the Wei 2-22, the gas-oil ratio GOR=18.8, the solubility coefficient α=4.24, the saturation pressure P_(b)=3.82, the formation crude oil density ρ_(o)=0.8633, and the formation crude oil viscosity μ_(o)=9.39, which are real high-pressure physical property parameters of the zone Ef1 of this oil reservoir. 

What is claimed is:
 1. A method for distinguishing an authenticity of high-pressure physical property parameters of an oil reservoir, comprising the following steps: 1) collecting the high-pressure physical property parameters: collecting the high-pressure physical property parameters of a sampled well of the oil reservoir to be distinguished, wherein the high-pressure physical property parameters comprise a gas-oil ratio GOR, a solubility coefficient α, a saturation pressure P_(b), a formation crude oil density ρ_(o), and a formation crude oil viscosity μ_(o); 2) screening a standard well: determining the standard well from multiple oil wells continuously exploited in a same block and a same zone as the sampled well, wherein an indicator diagram of the standard well reflects a pump of the standard well does not leak and a tubing string of the standard well does not leak, and meanwhile, the standard well has a lowest water content, a highest liquid yield and a largest submergence in the multiple oil wells; 3) calculating a pump efficiency: substituting each group of the high-pressure physical property parameters collected in step 1) and related data of the standard well screened in step 2) into the following formula, and calculating a theoretical pump efficiency η_(theory) and a real pump efficiency η_(reality) of the standard well: $\eta_{theory} = {{\frac{S - \lambda}{S}\beta} - \frac{Q_{leak}}{Q_{theory}}}$ $\lambda = {\frac{\pi\; D^{2}\rho\;{gh}}{4\; E}\left( {\frac{L_{1}}{f_{1}} + \frac{L_{2}}{f_{2}} + \ldots + \frac{L_{n}}{f_{n}} + \frac{L_{p}}{f_{t}}} \right)}$ $\beta = \frac{1}{1 + \frac{\left( {{GOR} - {\alpha\; P_{s}}} \right)\left( {1 - f_{w}} \right)}{\left( {{10\; P_{s}} + 1} \right)}}$ when P_(s)≥P_(b), making P_(s)=P_(b), wherein if an oil pipe is anchored, L_(p)/f_(t) is not comprised in λ; η_(reality) =Q _(reality) /Q _(theory)*100%; Q _(theory) =πD ² ρgSN/4; Q _(leak) =πDρgδ ³ h/(12L _(p)/μ); ρ=(1−f _(w))*ρ_(o) +f _(w)*ρ_(w); h=h _(dynamic)+1000*(p _(oil) −p _(casing))*g/ρ; P _(s) =p _(casing)+(h _(setting) −h _(dynamic))*ρ_(o) *g/1000; μ=f _(w)+(1−f _(w))*μ_(o); wherein Q_(reality) represents a real output of an oil well of the multiple oil wells; Q_(theory) represents a theoretical displacement of the oil well of the multiple oil wells; Q_(leak) represents a pump leakage; the GOR represents the gas-oil ratio and a unit of the GOR is m³/m³; α represents the solubility coefficient and a unit of the solubility coefficient is m³/(m³·Mpa); P_(b) represents the saturation pressure and a unit of the saturation pressure is Mpa; ρ_(o) represents the formation crude oil density and a unit of the formation crude oil density is t/m³; μ_(o) represents the formation crude oil viscosity and a unit of the formation crude oil viscosity is Pa·S; λ represents a stroke loss of the standard well and a unit of the stroke loss is m; β represents a gas influence coefficient of the standard well, wherein the gas influence coefficient is dimensionless; ρ represents a mixed liquid density of the standard well and a unit of the mixed liquid density is t/m³; h represents a pump lift of the standard well and a unit of the pump lift is m; P_(s) represents a submergence pressure of the standard well and a unit of the submergence pressure is Mpa; μ represents a hydrodynamic viscosity of the standard well and a unit of the hydrodynamic viscosity is Pa·S; f_(w) represents a rate of a water content of a pumped liquid in the standard well; h_(dynamic) represents a dynamic liquid level depth of the standard well and a unit of the dynamic liquid level depth is m; D represents a pump diameter of the standard well and a unit of the pump diameter is m; h_(setting) represents a pump setting depth of the standard well and a unit of the pump setting depth is m; p_(oil) represents a wellhead oil pressure of the standard well and a unit of the wellhead oil pressure is Mpa; P_(casing) represents a casing pressure of the standard well and a unit of the casing pressure is Mpa; S represents a stroke length of the standard well and a unit of the stroke length is m; N represents a stroke frequency of the standard well and a unit of the stroke frequency is 1/min; L₁, L₂ and L_(n) respectively represent a length of a first-level rod, a length of a second-level rod and a length of an n-level rod of the standard well and a unit of the length is m; f₁, f₂ and f_(n) respectively represent a cross-sectional area of a first-level rod, a cross-sectional area of a second-level rod and a cross-sectional area of an n-level rod of the standard well and a unit of the cross-sectional area is m²; L_(p) represents a pump depth of the standard well and a unit of the pump depth is m; f_(t) represents a cross-sectional area of a metal part of the oil pipe of the standard well and a unit of the cross-sectional area is m²; E represents an elastic modulus of a steel of a pumping rod in the standard well, and E is 2.1*10⁷ N/cm²; g represents a gravity acceleration of the standard well and a unit of the gravity acceleration is m/s²; δ represents an annular gap between a pump plunger and a pump cylinder of the standard well and a unit of the annular gap is m; L_(pl) represents a length of the pump plunger of the standard well and a unit of the length of the pump plunger is m; and ρ_(w) represents a water density of the standard well and a unit of the water density is t/m³; and 4) screening results: after the pump efficiency is calculated in the step 3), for the standard well screened in step 2) and the each group of the high-pressure physical property parameters collected in step 1), obtaining a group of the theoretical pump efficiency η_(theory) and the real pump efficiency η_(reality), and for each group of the theoretical pump efficiency η_(theory) and the real pump efficiency η_(reality), calculating an absolute value Δ=|η_(theory)−η_(reality)| of an absolute error, and taking a smallest absolute value Δ_(min) of the absolute error: Δ_(min)=|η_(theory)−η_(reality)|; wherein if Δ_(min) meets a condition: Δ_(min)≤ε, wherein ε is a set accuracy, and 0≤ε≤0.02, the high-pressure physical property parameters corresponding to the group of the theoretical pump efficiency η_(theory) and the real pump efficiency η_(reality), comprising the gas-oil ratio GOR, the solubility coefficient α, the saturation pressure P_(b), the formation crude oil density ρ_(o), and the formation crude oil viscosity μ_(o), are real high-pressure physical property parameters of the oil reservoir to be distinguished. 